System and method for dissolved gas detection

ABSTRACT

A subsea mud evaluation system includes a blowout preventer (BOP), coupled to a wellbore formed in an underground formation, the blowout preventer being positioned proximate a sea floor. The system also includes a riser fluidly coupled to the BOP, the riser extending from the BOP to a sea surface location to transport drilling mud between the wellbore and the sea surface location. The system further includes a dissolved gas detection and mitigation systems (DMS), fluidly coupled to at least one of the BOP or the riser, the DMS receiving a quantity of drilling mud and determining a subsea bubble point of the quantity of drilling mud, corresponding to a pressure where a dissolved gas within the drilling mud is liberated.

BACKGROUND 1. Field of the Invention

The present disclosure relates to oil and gas drilling operations, and more specifically, to monitoring downhole operations to detect potential disturbances.

2. Description of Related Art

During oil and gas exploration operations, a wellbore may be drilled into a formation through a potential hydrocarbon-bearing region. Drilling mud is utilized to cool a drill bit that drills the formation, to carry cuttings from the bottom of the borehole to a surface location, and to supply hydrostatic pressure to regulate downhole pressures. When in contact with the formation and/or region, gas may enter the drilling mud and under high pressures the gas may dissolve in the mud. At certain pressures, the dissolved gases may be liberated from the mud, for example when the pressure is reduced, which may cause disturbances. For example, the dissolved gases may expand and drive mud out of the wellbore and/or a drilling riser, which drops the pressure of the wellbore, leading to additional liberation of dissolved gases. These situations are undesirable and create potentially hazardous scenarios.

SUMMARY

Applicants recognized the problems noted above herein and conceived and developed embodiments of systems and methods, according to the present disclosure, for downhole monitoring and control.

In an embodiment, a subsea mud evaluation system includes a blowout preventer (BOP), coupled to a wellbore formed in an underground formation, the blowout preventer being positioned proximate a sea floor. The system also includes a riser fluidly coupled to the BOP, the riser extending from the BOP to a sea surface location to transport drilling mud between the wellbore and the sea surface location. The system further includes a dissolved gas detection and mitigation systems (DMS), fluidly coupled to at least one of the BOP or the riser, the DMS receiving a quantity of drilling mud and determining a subsea bubble point of the quantity of drilling mud, corresponding to a pressure where a dissolved gas within the drilling mud is liberated.

In another embodiment a subsea mud evaluation system includes a blowout preventer (BOP), coupled to a wellbore at a sea floor, a riser fluidly coupled to the BOP, the riser extending from the BOP to a sea surface location to transport drilling mud between the wellbore and the sea surface location, and a dissolved gas detection and mitigation systems (DMS), fluidly coupled to the BOP. The DMS includes a first pressure chamber, an inlet flow path directing drilling mud from the BOP into the first pressure chamber, and one or more first sensors detecting one or more first properties of the drilling mud in the first pressure chamber. The system also includes a bubble point analysis system (BPAS), fluidly coupled to the riser including a second pressure chamber, the second pressure chamber receiving drilling mud from the riser and one or more second sensors detecting one or more second properties of the drilling mud in the second pressure chamber. The system further includes a control system, communicatively coupled to the BPAS and the DMS, the control system receiving information from the one or more first sensors and the one or more second sensors to determine a difference between a DMS bubble point and a BPAS bubble point.

In an embodiment, a method for monitoring drilling operations includes obtaining, at a subsea location, a first quantity of drilling mud. The method also includes determining, from the first quantity of drilling mud, a subsea bubble point pressure. The method further includes obtaining, at a surface location, a second quantity of drilling mud. The method also includes determining, from the second quantity of drilling mud, a surface bubble point pressure. The method includes determining a threshold pressure, based at least in part on a difference between the surface bubble point pressure and the subsea bubble point pressures.

BRIEF DESCRIPTION OF DRAWINGS

The foregoing aspects, features, and advantages of the present disclosure will be further appreciated when considered with reference to the following description of embodiments and accompanying drawings. In describing the embodiments of the disclosure illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.

FIG. 1 is a schematic side view of an embodiment of an offshore drilling operation, in accordance with embodiments of the present disclosure;

FIG. 2 is a schematic view of an embodiment of a detection and mitigation system, in accordance with embodiments of the present disclosure;

FIG. 3 is a schematic diagram of an embodiment of a sample evaluation environment, in accordance with embodiments of the present disclosure;

FIG. 4 is a schematic diagram of an embodiment of a mud evaluation environment, in accordance with embodiments of the present disclosure;

FIG. 5 is a flow chart of an embodiment of a method for determining bubble point pressures, in accordance with embodiments of the present disclosure;

FIG. 6 is a flow chart of an embodiment of a method for determining bubble point pressures, in accordance with embodiments of the present disclosure; and

FIG. 7 is a flow chart of an embodiment of a method for determining bubble point pressures, in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

The foregoing aspects, features, and advantages of the present disclosure will be further appreciated when considered with reference to the following description of embodiments and accompanying drawings. In describing the embodiments of the disclosure illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.

When introducing elements of various embodiments of the present disclosure, the articles “a”, “an”, “the”, and “said” are intended to mean that there are one or more of the elements. The terms “comprising”, “including”, and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Any examples of operating parameters and/or environmental conditions are not exclusive of other parameters/conditions of the disclosed embodiments. Additionally, it should be understood that references to “one embodiment”, “an embodiment”, “certain embodiments”, or “other embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, reference to terms such as “above”, “below”, “upper”, “lower”, “side”, “front”, “back”, or other terms regarding orientation or direction are made with reference to the illustrated embodiments and are not intended to be limiting or exclude other orientations or directions.

Embodiments of the present disclosure include systems and methods for detection of dissolved gases during drilling and/or exploration operations. The dissolved gases may be detected and drilling operations may be alerted, allowing the operator to adjust operating conditions to mitigate the dissolved gases. In various embodiments, a pump or turbine may be utilized to reduce a pressure of an isolated sample of drilling mud, including dissolved gases, to remove the gas in a controlled environment separate from the wellbore. Systems and methods of the present disclosure provide the benefit of proactively identifying dissolved gases prior to upsets, rather than reacting to dissolved gases, as is the practice with existing systems. Furthermore, because the system may proactively identify dissolved gases, operations may continue without implementing mitigation systems in scenarios where they are unneeded.

Embodiments of the present disclosure are directed toward overcoming problems associated with gases from underground formations dissolving into drilling mud at high pressure. These gases are undetectable using current technologies. When the mud is at a lower pressure, such as when the mud is carried upward toward a surface location, the gases are liberated from the mud (e.g., boil out of the mud) and can accelerate the mud upward and out of a drilling riser. In other words, the mud is not becoming a gas, and instead a separate chemical trapped in the mud is what bubbles out.

If the level of the mud is lowered, the integrity of the well can be compromised, leading to a blowout or other loss of containment event. Even if a blowout preventer (BOP) is closed, gases in contaminated mud in the riser above the BOP can still be liberated. The escape of these gases creates potential hazards, for example environmental risks and/or exposure to personnel, not to mention financial risks to operators. Present embodiments overcome these difficulties by adding a flow loop to the drilling operation, for example in a location upstream (uphole), downstream (downhole), or incorporated into the BOP. Within this loop are valves that trap a volume. A pump or turbine lowers the pressure of the drilling mud in this trapped volume to the point that liberation occurs. Alternatively, a propeller of the turbine spins and causes cavitation in the drilling mud. Furthermore, in various embodiments, a Venturi tube that lowers the pressure by accelerating the mud through a restriction may be used. When the pressure in the mud drops to a critical point, gases dissolved in the mud are liberated. Another embodiment uses a cylinder to increase the volume that the trapped fluid is in. Acoustic sensors detect the initiation of gas liberation, and pressure sensors log the pressure when it occurs. In embodiments, sensors may include active ultrasonic (UT) sensors that send a signal and evaluate one or more reflections off of bubbles and/or passive acoustic sensors that listen for the creation or collapse of bubbles (e.g., cavitation). Furthermore, various embodiments may also utilize pressure and volume (e.g., position) sensors to determine changes in compressibility (bulk modulus), such as those sensors described in U.S. Pat. No. 9,328,609, which is hereby incorporated by reference in its entirety. The pressure is compared to reference pressures for the mud chemistry and mixture, and if the pressure is above the reference pressure for contaminated mud (or above a defined level), then an alert is sent to the driller so that prevention and mitigation operations can be followed. Various embodiments also include automated safety measures, such as closing the BOP, closing a diverter to contain riser fluids, pressuring the riser to prevent gases, and the like upon detection of dissolved gases. Furthermore, embodiments may include coupling the volume to choke/kill lines so that the volume of mud below the BOP may be purged of gas and captured while the BOP is closed.

Embodiments of the present disclosure present various advantages over prior art systems. By way of example only, improved environmental protection is provided as gases can be detected and contained in situations where they currently may not be detected until after release. Additionally, improved worker safety in escaping gases may be flammable, caustic, or otherwise subject works to undesirable work environments. Furthermore, operations may be improved because protections (such as a closed diverter) may be implemented when there is an actual risk of dissolved gases, rather than being in continuous operations. In various embodiments, the present disclosure provides an early-warning system and can be configured to automatically trigger safety processes, such as closing the BOP and diverter. Additionally, embodiments may be adapted to facilitate decontaminating the mud below the BOP in a safe and controlled process.

FIG. 1 is a side schematic view of an embodiment of subsea drilling operation 100. The drilling operation includes a vessel 102 floating on the sea surface 104 substantially above a wellbore 106. It should be appreciated that the vessel 102 is shown for illustrative purposes only, and in various embodiments, other structures such as drilling platforms may be utilized with embodiments of the present disclosure. A wellbore housing 108 sits at the top of the wellbore 106 and is connected to a blowout preventer (BOP) assembly 110, which may include shear rams 112, sealing rams 114, and/or an annular ram 116. One purpose of the BOP assembly 110 is to help control pressure in the wellbore 106. The BOP assembly 110 is connected to the vessel 102 by a riser 118. During drilling operations, a drill string 120 passes from a rig 122 on the vessel 102, through the riser 118, through the BOP assembly 110, through the wellhead housing 108, and into the wellbore 106. The lower end of the drill string 120 is attached to the drill bit 124 that extends the wellbore 106 as the drill string 120 turns. It should be appreciated that while a drilling operation is illustrated, embodiments of the present disclosure may also be incorporated into logging operations, stimulation operations, recovery operations, and the like. Additional features shown in FIG. 1 include a mud pump 126 with mud lines 128 connecting the mud pump 126 to the BOP assembly 110, and a mud return line 130 connecting the mud pump 126 to the vessel 102. It should be appreciated that the illustrated mud pump 126 is at a subsea location, but in other embodiments, the mud pump 126 may be arranged on the vessel 102. Moreover, in embodiments, the mud pump 126 may receive a mud supply from a pit or mud shake on the vessel 102. A remotely operated vehicle (ROV) 132 can be used to make adjustments to, repair, or replace equipment as necessary. Although the BOP assembly 110 is shown in the figures, the wellhead housing 108 could be attached to other well equipment as well, including, for example, a tree, a spool, a manifold, or another valve or completion assembly.

One efficient way to start drilling the wellbore 106 is through use of a suction pile 134. Such a procedure is accomplished by attaching the wellhead housing 108 to the top of the suction pile 134 and lowering the suction pile 134 to a sea floor 136. As interior chambers in the suction pile 134 are evacuated, the suction pile 134 is driven into the sea floor 136, as shown in FIG. 1, until the suction pile 134 is substantially submerged in the sea floor 136 and the wellhead housing 108 is positioned at the sea floor 136 so that further drilling can commence. As the wellbore 106 is drilled, the walls of the wellbore are reinforced with steel casings 138 that provide stability to the wellbore 108, and may also be cemented to the formation, and help to control pressure from the formation.

During operations, such as drilling operations, mud is injected into the wellbore 106 via the drilling string 120. For example, the mud pump 126 may receive drilling mud from the vessel 102 and direct the mud through the drill string 120. The mud flows through the drilling string 120 and exits at the drill bit 124, carrying rock cuttings away from the bit 124 and also cooling the bit. The mud enters an annulus 140 surrounding the drill string 120. Advantageously, this mud may be utilized to provide pressure control within the wellbore 106, for example, to balance pressures from the formation. The mud may fill the wellbore 106 and the riser 118, where it is returned to the vessel 102 for processing and reuse. The formation may include a hydrocarbon producing zone that contacts the mud. In various embodiments, gases may enter the mud and at high pressures be entrained (e.g., dissolved) within the mud. As the mud returns to the vessel 102, the pressure may drop, causing the gas to liberate and expand, which may cause operational upsets, as described above. Embodiments of the present disclosure are directed toward systems and methods to detect the dissolved gases within the mud, and subsequently, mitigate the dissolved gases before operational upsets occur.

Embodiments of the present disclosure illustrate a flow loop and chamber coupled to the BOP creating a subsea mud-gas separator. The chamber is surrounded by seawater to permit a constant, known temperature. Valves close off the chamber, and a pump or cylinder lowers the pressure of the mud to initiate degassing. In embodiments, a prop spins and causes cavitation in the drilling mud. Additionally, in certain embodiments, a pump could move the mud through a Venturi tube to lower its pressure and initiate gas liberation. Acoustic sensors detect the initiation of bubbling, and pressure sensors detect the pressure, which is compared to references for the mud chemistry and mixture. If the pressure is above the mud's baseline (or above a defined threshold), then an alert is sent to the driller so that prevention and mitigation operations are enacted. Specific muds may be designed to have consistent degassing baselines. In embodiments that change the volume of chamber, then position (e.g., volume) sensors can be used with the pressure sensor to detect a change in compressibility (bulk modulus) of the mud.

FIG. 2 is a schematic perspective view of an embodiment of a BOP system 200, which may be similar to the BOP 110, coupled to a wellbore. The BOP system 200 includes various features, which will not be described herein for clarity, and is coupled to the wellbore via a wellhead connector 202. In the illustrated embodiment, the BOP system 200 is fluidly coupled to the riser 118, which may be filled with drilling mud during drilling operations. For example, mud may be returned to the vessel via the riser. As mud is transported to the surface, the resultant pressure drop may lead to liberation of the gas entrained within the mud, which expands and may displace the mud. In other words, degassing the mud to remove the dissolved gases may displace the liquid/solid portion of the mud. Such displacement is undesirable and may negatively affect wellbore operations. Embodiments of the present disclosure include a dissolved gas detection and mitigation system 204 (e.g., system, detector, DMS) to identify dissolved gas within the drilling mud and, in embodiments, perform one or more operations to mitigate and remove the dissolved gas from the mud.

In the illustrated embodiment, the DMS 204 is shown as a line drawing for clarity, but it should be appreciated that the DMS 204 may be constructed as a vessel having sufficient temperature and pressure capabilities for operation in subsea environment. The illustrated DMS 204 includes an inlet flow path 206 extending toward a first valve 208, which may also be referred to as an inlet valve or an isolation valve. The first valve 208 may move between open and closed positions to enable mud to enter the DMS 204. As shown, the inlet flow path 206 is coupled to the BOP system 200; however, it should be noted that the DMS 204 may be arranged upstream (e.g., uphole, along the riser) or downstream (e.g., downhole, below the BOP) in various other embodiments. It may be advantageous to position the DMS 204 along the riser (e.g., above the BOP, closer to the surface than the BOP) due to installation procedures. However, such a position may cause difficulties with obtaining mud that is shut in below the BOP. Additionally, in embodiments, it may be advantageous to position the DMS 204 below the BOP for access to the mud at an earlier position, however, the DMS 204 may then be constructed to different pressure and temperature standards, as the DMS 204 may be considered part of the pressure barrier with the wellbore. Moreover, it should be noted that embodiments may be described with reference to a subsea well, but systems may also be incorporated into surface wells. Furthermore, in an embodiment with a Venturi tube, the first valve 208 may not be used. However, the first value 208 may be utilized where the trapped volume is in the form of a closed loop isolated from the wellbore mud and circulated through the Venturi tube. Or, in embodiments, it could be an open loop that just perpetually pumps mud from the wellbore through the Venturi tube and back into the wellbore.

Continuing with the DMS 204, a fluid mover 210 directs fluid toward an outlet flow path 212. The fluid mover 210 may include a pump, a turbine, or various other devices that may be utilized to drive fluid through the DMS 204. As noted herein, the fluid mover 210 may be utilized to reduce a pressure of mud within the DMS 204 in order to identify a pressure at which the dissolved gases are liberated. A chamber 214 includes a trapped volume (e.g., liquid volume) arranged between the first valve 208 and the fluid mover 210. The chamber 214 may receive a predetermined volume of liquid (e.g., mud) where the pressure is reduced in order to identify a pressure where the dissolved gases are liberated from the mud. The chamber 214 may include a variety of sensors, such as a first sensor 216 corresponding to an acoustic sensor and a second sensor 218 corresponding to a pressure sensor. The pressure sensor 218 may identify the pressure within the chamber 214 while the acoustic sensor 216 identifies liberation of the dissolved gases. A second valve 220 may be coupled to the chamber 214 to direct gases out of the chamber 214, for example, by tying into the choke/kill lines.

In operation, mud may return to the vessel through the riser. Often, this mud has contacted the formation, and as a result, may include dissolved gases due to the high pressure environment associated with the downhole environment. The mud may travel through the BOP system 200 and into the riser 118. As noted, dissolved gases in the mud may be liberated as the pressure is reduced, such as when the mud is transported to the surface. Accordingly, in various embodiments, the inlet flow path 206 may direct a volume of mud into the DMS 204. The mud may be directed toward the chamber 214. The first valve 208 may be closed and the fluid mover 210 may reduce a pressure within the chamber 214. The pressure sensor 218 may monitor the pressure while the acoustic sensor 216 monitors for liberation of the gases. Upon detection of liberation, the pressure sensor 218 may transmit information, for example data corresponding to the liberation pressure, to a control system for evaluation. In various embodiments, mitigation efforts may begin, such as releasing the gases into the kill/choke line via the second valve 220.

Whether a gas dissolves in drilling mud is generally a function of pressure, temperature, gas composition, and mud chemistry. As a result, it may be challenging to predict when, and what quantity, of gas will dissolve within the drilling mud. Phase diagrams may be utilized in part, but different gases will dissolve in different quantities at different rates under different conditions. Accordingly, embodiments of the present disclosure may determine a baseline level for uncontaminated (e.g., no dissolved gases) mud, or a baseline of a mud with a known amount of gas dissolved in it, and evaluate the baseline against information obtained from the DMS 204. For example, the uncontaminated mud may be obtained at the vessel and maintained at similar conditions as the DMS 204 at the wellbore (e.g., same pressure and temperature). In various embodiments, the DMS 204 mimics or substantially mimics a variety of variables, such as pressure, temperature, composition/chemistry, time at conditions, etc. For example, because time may be a factor, controller equipment may include a clock function that tracks time at conditions as well as temperature, pressure, etc. A bubble point for the uncontaminated mud may be determined, along with a second bubble point for the contaminated mud in the DMS 204. The difference between the measurements may then be evaluated to determine whether a condition will occur within the riser that would lead to liberation of the gas, which may enable mitigation prior to transporting the mud to the surface. For example, mitigation may include closing in the BOP system 200 and circulating to remove contamination. Additionally, in embodiments, mitigation may include removing the gases, for example, via the chamber 214.

FIG. 3 is a schematic diagram of a sample evaluation environment 300 including a surface environment 302 and subsea environment 304. In various embodiments, the surface environment 302 is arranged at the vessel and may be controlled by operators. As noted above, it may be desirable to obtain a baseline reading for the mud utilized in the drilling operation. The surface environment 302 includes a mud pit 306 (e.g., mud shake) that includes drilling mud, which may come from the riser or from a different source. The mud within the mud pit 306 may be the same composition as mud utilized in drilling operations. The illustrated mud pit 306 is presented by way of example only and additional equipment such as agitators and other mechanical degassing equipment, may also be utilized to decontaminate the mud. In the illustrated embodiment, a bubble point analysis system 308 (BPAS) may be utilized in order to determine a bubble point for the uncontaminated mud. It should be appreciated that bubble point refers to a boundary between gas and liquid phases in a phase diagram. For example, the bubble point may be presented by a temperature and pressure (among other factors, such as time at those conditions, because phase change can be a time-dependent phenomenon) where a first bubble of vapor is formed, such as by heating, chilling, and/or lowering a pressure of a liquid consisting of two or more components. In other words, determining the bubble point determines the pressures at which liberation of dissolved gases occurs. However, it should be appreciated that an alternative process within the scope of the present disclosure is to dissolve a known and safe amount of a specific gas into the fully decontaminated mud and then degas that to get a reference point. This alternative process may make it easier to get the reference data point for bubble point.

The BPAS 308 includes a second fluid mover 310, which may be a pump, and a pressure chamber 312. Mud is directed into the pressure chamber 312 and the pressure is decreased. The pressure may be monitored by a third sensor 314, which may be a pressure sensor. Moreover, in various embodiments, a heater/chiller 316 may be incorporated in order to maintain a substantially constant temperature, which may be evaluated via a fourth sensor 318, which may correspond to a temperature sensor. Moreover, in various embodiments, a fifth sensor 320 may be included, such as an acoustic sensor to detect bubbling of the mud within the pressure chamber 312.

Mud may be directed into the pressure chamber 312 and the pressure may be reduced in order to identify a bubble point for the particular mud chemistry at the pressure and temperature. As a result, a first bubble point may be identified, which may also be referred to as a bubble point at the surface. In various embodiments, the pressure utilized to identify the first bubble point may be substantially similar to the pressure of the chamber 214 in the subsea environment 304. For example, the second sensor 218 may transmit information to the surface and the pressure established within the pressure chamber 312 may be set to be substantially equal to the pressure identified by the second sensor 218. However, it should be appreciated that other pressures may be utilized. For example, a variety of different pressures may be utilized to establish a variety of different bubble points for the mud at a variety of different pressures and/or temperatures. As a result, a plot may be established to identify the bubble points (e.g., a curve on a Pressure-Temperature chart) along the riser 118. Where that line is depends on the mixture/chemistry of the mud and also the dissolved gas. The curve on the P-T chart may have a time component (e.g., within 1 minute). The shorter the time, the farther out (higher temperature and lower pressure) the curve will be, meaning a lower pressure is needed to initiate bubbling if you want to see bubbles within 10 sec instead of 1 min.

The illustrated surface environment 302 includes a control system 322, which is illustrated as a singular, integrated unit for simplicity, but may include a variety of different components communicatively coupled to one another. Various components of the control system 322 may also be positioned remote from the surface environment 302, for example, at a server that is accessible via the control system 322. Moreover, the control system 322 may correspond to one or more computer systems that include one or more processors and/or memories that may execute programmed instructions. The control system 322 may include onboard components and/or may communicate with a distributed computing environment, which may be utilized to perform one or more steps of the instructions carried out by the control system 322. The control system 322 includes an interface 324 for receiving information from the various sensors 314, 318, 320 at the surface. Moreover, the sensors 216, 218 may also provide information to the control system 322 at the interface 324. An identification module 326 may receive information, for example from the acoustic sensors 216, 320 to identify respective bubble points. For example, the sensors 216, 320 may transmit information indicative of a sound within a respective chamber, the sound may have a value that is compared against a threshold value. Values above the threshold may be determined to identify bubbling while values below the threshold value do not. It should be appreciated that various filters may also be incorporated to reduce noise and the like in the measurements.

The control system 322 further includes a riser evaluation module 328. The riser evaluation module 328 performs one or more calculations to identify a location, along the riser 118, where mud may reach the bubble point. In certain embodiments, various sensors may be arranged along the riser 118 (not pictured) to provide readings along the riser 118. As will be appreciated, the riser 118 may be pressurized, for example, based at least in part on a mud pressure injected into the wellbore 106. Moreover, in embodiments, additional controls may be deployed in order to establish and maintain a pressure within the riser. Furthermore, riser pressure may, at least in part, be a function of a vertical location along the riser. That is, pressure increases with depth. As a result, “deeper” or “lower” locations (relative to the sea surface 104) will have higher pressures than “shallower” or “higher” locations (relative to the sea surface 104). This information may be utilized by the riser evaluation module 328 to identify different pressure regions along the riser 118. As a result, mud pressure along the riser 118 may be calculated.

Information from the riser evaluation module 328 may be utilized by an action module 330, which may determine whether an action is performed, based at least in part on a determination regarding the bubble point of the mud along the riser 118. For example, the riser evaluation module 328 may determine a location along the riser 118, and time, where the mud is likely to reach the bubble point, which may create an undesirable well condition. It should be appreciated that the temperature profile of the mud in the wellbore and riser is not constant, and the combination of pressure, temperature, and the time the mud has been in a bubble-prone condition can be used to calculate the point of bubbling. As a result, the action module 330 may perform one or more actions, such as providing an alarm or notification to an operator. In various embodiments, the action module 330 may automatically trigger remediation techniques, such as closing in the BOP 110, circulating mud to remove contamination, adjusting a pressure within the riser 118, or removing the dissolved gas via the DMS 204. Accordingly, systems and methods are directed toward bubble point identification along the riser 118 and performing one or more actions in response to determining a potentially undesirable well condition. These systems and methods provide an improvement over existing systems where bubble point is unknown along the riser and operators reactively respond to undesirable well conditions.

The illustrated embodiment further includes the subsea environment 304, which may share one or more features of the BOP system 200 described with respect to FIG. 2. For example, the subsea environment 304 illustrates the DMS 204 coupled to the BOP 110. The DMS 204 receives mud via the inlet flow path 206, which may direct the mud into the chamber 214. Closing the first and second valves 208, 220 isolates the mud within the chamber 214, where the fluid mover 210 may be utilized to adjust the pressure to determine the bubble point, for example, via the first sensor 216. Information from the sensors 216, 218 may be transmitted to a surface location via a communication system 332, which may correspond to a wired or wireless data transmission system, such as wired drill pipe or the like. By way of example, wired drill pipe and acoustic transmission can be done for transmitting info inside the riser. An umbilical or sonar can be used to transmit info outside the riser. Moreover, embodiments may also piggyback on the BOP control lines. As noted, information received from the subsea environment 304 may be utilized to determine a location along the riser where the mud may reach the bubble point (e.g., the pressure corresponding to the bubble point) and potentially create a disturbance.

The subsea environment 304 may also include a mitigation system 334, which may enable preventative or proactive adjustments to the mud. For example, the mitigation system 334 may transmit instructions to the fluid mover 210 to circulate the mud out of the chamber 214, to adjust a position of the valves 208, 220, and the like. In this manner, surface instructions may be transmitted to the subsea environment 304 to enable mitigation and/or preventative actions to reduce the likelihood of well disturbances due to dissolved gases in the mud.

FIG. 4 is a schematic diagram of an embodiment of a mud evaluation environment 400 that may be utilized with embodiments of the present disclosure. The mud evaluation is provided for illustrative purposes only and may include additional systems or fewer systems. For example, in various embodiments, the environment 400 may include safety systems (e.g., diverter, pressurizing the riser) and the like, which have been omitted here for clarity. It should be appreciated that one or more components of the mud evaluation environment 400 may be associated with one or more of the surface or subsea environments 302, 304. The illustrated mud evaluation environment is communicatively coupled to the BOP system 200, for example, via the communication system 332. In various embodiments, the mud evaluation environment 400 may evaluate a baseline bubble point, determined at a surface location, and compare the baseline bubble point to a subsea bubble point. A difference may be determined to illustrate how pressure or temperature changes in the mud may lead to liberating of dissolved gases within the mud. This difference may be evaluated with respect to a riser that receives the mud to return the mud to the surface. Evaluation of the mud, with may be specific to the mud chemistry, may enable one or more actions to be proactively initiated to avoid or reduce the likelihood of undesirable well conditions.

The mud evaluation environment 400 includes one or more processors 402 and one or more memories 404, as described above. The memory may be a non-transitory machine-readable medium that stores instructions that are executed by the one or more processors 402. As previously noted, the one or more processors 402 and/or the one or more memories 404 may be local to the environment 400 and/or may be communicatively coupled to the environment 400, for example, as part of a distributed computing environment. Further included are an input source 406 and display 408. The input source 406 may include a keyboard, mouse, touchscreen, or the like and receive instructions, which are displayed on the display 408.

In various embodiments, a surface bubble point module 410 determines a bubble point at the surface, for example, based on information from the sensors 314, 318, 320 coupled to the pressure chamber 312. The bubble point module 410 may be integrated into the identification module 326. Further illustrated is a subsea bubble point module 412, which determines a bubble point in the subsea environment, for example, based on information from the sensors 216, 218. The subsea bubble point module 412 may also be integrated into the identification module 326.

As previously discussed, pressures and temperatures along the riser 118, along with the speed of the mud (e.g., movement in the riser) in certain embodiments, may be determined to evaluate whether the mud will reach a bubble point pressure as the mud is transported to the surface or if operations could trigger liberating gases, such as by running equipment into the riser. For example, running a tool downhole through the riser may act as an agitator causing cavitation and liberating dissolved gases. The riser bubble point module 414 may be utilized to conduct at least a portion of the evaluation. For example, the bubble point in the subsea environment may be determined at the DMS 204 and then pressures and temperatures along the riser 118 are evaluated to determine whether that pressure will be reached, or a pressure within a threshold is reached, as the mud is transported to the surface. Furthermore, in embodiments, a difference between the bubble point determined at the surface (which may be uncontaminated mud) compared to the bubble point determined in the subsea environment (which may be contaminated mud) may also be evaluated with respect to a pressure change along the riser. Moreover, the determined bubble point in the subsea environment may be evaluated against a determined, real-time baseline (corresponding to the bubble point at the surface). If the bubble point is above the baseline, then an alarm may be triggered, as noted above, via the action module 330. Additionally, the action module 330 may actively initiate mitigation procedures, as discussed above.

In various embodiments, it may be desirable to identify trends associated with different formations and/or mud chemistries. This information may be evaluated using a machine learning system 422 that may receive historical information from a database 418 and mud information from a mud chemistry database 420. For example, historical bubble points may be compared to one or more aspects of the mud chemistry to determine whether trends or patterns may emerge. The historical information may also include formation information. For example, different gases may dissolve in different quantities at different pressures, and therefore, if the formation is known to include a particular gas that had dissolved at a certain pressure in a mud with similar chemistry to the instant operation, bubble point information from the previous drilling operation may be useful and provide insight for ongoing operations. Additional information may also be used, such as depth of wellbore, formation temperature(s), drilling mud temperature, mud pressure, formation pressure(s), time of exposure, and the like.

The machine learning system 422 may be utilized in various embodiments to predict potential operational upsets, for example, based on information from other drilling operations under similar conditions. For example, the historical database 418 and the mud chemistry database 420 may provide information, such as ground truth information, to the machine learning system 422 to recognize one or more patterns for evaluating and identifying potential operational disruptions. For example, drilling operations using similar mud chemistry and expected similar gases may provide valuable information to determining present potential bubble points. Over time, the machine learning system may acquire new information and update alarms and the like in order to enable dynamic adjustment of operations.

As indicated herein, systems and methods may be directed toward evaluating bubble point pressures (which have also been referred to as just bubble points) for drilling muds that contain dissolved gases. Identification of the bubble point may facilitate wellbore operations to reduce the likelihood of operational upsets and/or to enable mitigation and/or prevention operations in a proactive, rather than reactive, manner. For example, a baseline bubble point pressure, which may correspond to a pressure obtained at a surface location, may be utilized when evaluating a subsea bubble point pressure. If a difference between the two pressures exceeds a threshold amount, an alarm or indicator may be provided. Moreover, in embodiments, pressures along the riser may be estimated to determine whether the mud will reach a riser bubble point pressure as it returns to the surface. If so, remediation and/or prevention techniques are initialized prior to returning the mud to the surface.

FIG. 5 is a flow chart of a method 500 for determining a potentially undesirable operational condition. It should be appreciated that the method may include more or fewer steps. Moreover, the steps may be performed in any order, or in parallel, unless otherwise indicated. The example begins by determining a baseline bubble point pressure 502. For example, the baseline may be determined at a surface location, for example, by evaluating a bubble point pressure for an uncontaminated mud. As previously noted, the baseline bubble point pressure may be determined by arranging the mud within a pressure chamber and adjusting the pressure (e.g., increasing or decreasing the pressure), to determine a pressure where bubbles or liberation occurs, for example via information from an acoustic sensor. The method continues with determination of a subsea bubble point pressure 504. For example, the DMS described herein may be utilized to obtain a sample of contaminated mud, position the mud within a fluid volume, decrease a pressure of the mud, and then determine a pressure at which dissolved gases are liberated from the mud. In various embodiments, a difference between the baseline pressure and the subsea pressures are determined 506 and compared against a threshold 508. The threshold may be based, at least in part, on a likelihood that the mud will significantly decrease in pressure as it is returned to the surface location. In various embodiments, the threshold may be different for different mud chemistries, different formation properties, and the like. If the difference is below the threshold, the method ends 510. However, if the difference is above the threshold, one or more actions are performed 512. For example, an alarm may be transmitted to an operator. Additionally, in embodiments, remediation or mitigation actions may begin. For example, the gas may be removed from the subsea mud or the BOP may be shut in. In this manner, bubble point pressures may be determined and an operator may be made aware of a potentially undesirable condition.

FIG. 6 is a flow chart of an embodiment of a method 600 for determining a riser bubble point pressure. The example beings with determining a subsea bubble point pressure 602. As noted herein, a downhole sampling system may obtain a sample of contaminated mud to determine a bubble point pressure. Pressures along the riser may be estimated 604. For example, pressures may reduce as the mud travels toward the surface and out of the riser. Thereafter, the estimated pressures are compared to the subsea bubble point pressure 606 to determine whether the subsea bubble point pressure will be obtained as the mud flows out of the riser 608. If not, then the method may end 610. However, if the subsea bubble point pressure will be obtained, one or more actions may occur 612. For example, an alarm may be transmitted to an operator. Additionally, in embodiments, remediation or mitigation actions may begin. For example, the gas may be removed from the subsea mud or the BOP may be shut in. In this manner, the subsea bubble point pressure may be determined and pressures along the riser may be estimated to evaluate whether a dissolved gas liberation event will be reached within the riser.

FIG. 7 is a flow chart of an embodiment of a method 700 for determining a riser bubble point. The example beings with determining a subsea bubble point 702. As noted herein, a downhole sampling system may obtain a sample of contaminated mud to determine a bubble point. Determination of the bubble point may include a variety of pieces of information, such as pressure, temperature, time, machine learning data, and the like. In other words, a variety of factors and information, as described herein, may be utilized to determine the subsea bubble point. Conditions along the riser may be estimated 704. For example, pressures may reduce as the mud travels toward the surface and out of the riser, as noted above. Moreover, temperature may change, composition may change, time at certain conditions may impact the bubble point, and the like. Thereafter, the estimated conditions are compared to the subsea bubble point conditions 706 to determine whether the subsea bubble point conditions will be obtained as the mud flows out of the riser and/or if the mud is driven downhole 708. If not, then the method may end 710. However, if the subsea bubble point conditions will be obtained, one or more actions may occur 712. For example, an alarm may be transmitted to an operator. Additionally, in embodiments, remediation or mitigation actions may begin. For example, the gas may be removed from the subsea mud or the BOP may be shut in. In this manner, the subsea bubble point conditions may be determined and conditions along the riser may be estimated to evaluate whether a dissolved gas liberation event will be reached within the riser.

The foregoing disclosure and description of the disclosed embodiments is illustrative and explanatory of the embodiments of the invention. Various changes in the details of the illustrated embodiments can be made within the scope of the appended claims without departing from the true spirit of the disclosure. The embodiments of the present disclosure should only be limited by the following claims and their legal equivalents. 

1. A subsea mud evaluation system, comprising: a blowout preventer (BOP), coupled to a wellbore formed in an underground formation, the blowout preventer being positioned proximate a sea floor; a riser fluidly coupled to the BOP, the riser extending from the BOP to a sea surface location to transport drilling mud between the wellbore and the sea surface location; and a dissolved gas detection and mitigation systems (DMS), fluidly coupled to at least one of the BOP or the riser, the DMS receiving a quantity of drilling mud and determining a subsea bubble point of the quantity of drilling mud, corresponding to conditions where a dissolved gas within the drilling mud is liberated.
 2. The system of claim 1, wherein the DMS further comprises: a pressure chamber, the pressure chamber receiving the quantity of drilling mud; a fluid mover, the fluid mover reducing a pressure within the pressure chamber; and a first sensor, the first sensor detecting the bubble point of the quantity of drilling mud.
 3. The system of claim 2, wherein the first sensor is at least one of an acoustic sensor or a volume sensor.
 4. The system of claim 1, further comprising: a control system, the control system receiving first data from the first sensor and second data from a second sensor arranged at a chamber at the sea surface location, the control system determining a surface bubble point based at least in part on the second data.
 5. The system of claim 4, wherein the control system determines a threshold bubble point, based at least in part on a comparison between the subsea bubble point and the surface bubble point.
 6. The system of claim 1, further comprising: a kill/choke line coupled to the DMS, the coupling receiving dissolved gases from the quantity of drilling mud.
 7. The system of claim 1, wherein the DMS further comprises: a Venturi tube; and a fluid mover driving the mud through a reduced diameter portion of the Venturi tube.
 8. A subsea mud evaluation system, comprising: a blowout preventer (BOP), coupled to a wellbore at a sea floor; a riser fluidly coupled to the BOP, the riser extending from the BOP to a sea surface location to transport drilling mud between the wellbore and the sea surface location; and a dissolved gas detection and mitigation systems (DMS), fluidly coupled to the BOP, the DMS comprising: a first pressure chamber; an inlet flow path directing drilling mud from the BOP into the first pressure chamber; and one or more first sensors detecting one or more first properties of the drilling mud in the first pressure chamber; a bubble point analysis system (BPAS), fluidly coupled to the riser, the BPAS comprising: a second pressure chamber, the second pressure chamber receiving drilling mud from the riser; and one or more second sensors detecting one or more second properties of the drilling mud in the second pressure chamber; and a control system, communicatively coupled to the BPAS and the DMS, the control system receiving information from the one or more first sensors and the one or more second sensors to determine a difference between a DMS bubble point and a BPAS bubble point.
 9. The system of claim 8, wherein the DMS further comprises: a fluid mover, the fluid mover lowering a pressure of the first pressure chamber to liberate dissolved gases from the drilling mud.
 10. The system of claim 8, wherein the one or more first sensors and the one or more second sensors include acoustic sensors, pressure sensors, temperature sensors, volume sensors, or a combination thereof.
 11. The system of claim 8, wherein the DMS is coupled to a kill/choke, the kill/choke line transporting gases from the first pressure chamber.
 12. The system of claim 8, wherein the DMS further comprises: an outlet flow path, coupled to the BOP, to circulate drilling mud out of the first pressure chamber and back toward the BOP.
 13. The system of claim 8, wherein drilling mud in the DMS and the drilling mud in the BPAS is maintained at substantially similar conditions.
 14. The system of claim 8, further comprising: an alarm system, the alarm system transmitting a signal in response to a determination that a difference between the DMS bubble point and the BPAS bubble point exceeds a threshold.
 15. The system of claim 14, wherein the signal initiates an alarm indication, a mitigation event, or a combination thereof.
 16. A method for monitoring drilling operations, comprising: obtaining, at a subsea location, a first quantity of drilling mud; determining, from the first quantity of drilling mud, a subsea bubble point pressure; obtaining, at a surface location, a second quantity of drilling mud; determining, from the second quantity of drilling mud, a surface bubble point pressure; and determining a threshold pressure, based at least in part on a difference between the surface bubble point pressure and the subsea bubble point pressures.
 17. The method of claim 16, further comprising: determining a riser pressure at a location along a riser; determining the riser pressure exceeds the threshold; and providing an alert.
 18. The method of claim 17, further comprising: in response to receiving the alert, performing one or more mitigation actions to remove a dissolved gas from the first quantity of drilling mud.
 19. The method of claim 16, further comprising: determining a mud pressure will exceed the threshold; and shutting a blowout preventer.
 20. The method of claim 16, further comprising: reducing a pressure of the first quantity of drilling mud; receiving, from a sensor, information indicative of liberation of the drilling mud; and determining the information exceeds a second threshold. 